1. Field of the Invention
This invention relates to a process for thermally insulating a well. More specifically, the invention relates to a process for insulating an upper portion of a tubing string in a wellbore with silicate foam and leaving a lower portion of the tubing string uninsulated.
2. Description of the Prior Art
In the recovery of heavy petroleum crude oils, the industry has for many years recognized the desirability of thermal stimulation as a means for lowering the oil viscosity and thereby increasing the production of oil.
One form of thermal stimulation which has recently received wide acceptance by the industry is a process of injecting steam into the well and into the reservoir. This process is a thermal drive technique where steam is injected into one well and the steam drives oil before it to a second, producing well. In an alternative method, a single well is used for both steam injection and production of the oil. The steam is injected through the tubing and into the formation. Injection is then interrupted, and the well is permitted to heat soak for a period of time. Following the heat soak, the well is placed on a production cycle, and the heat fluids are withdrawn by way of the well to the surface.
Steam injection can increase oil production through a number of mechanisms. The viscosity of most oils is strongly dependent upon its temperature. In many cases, the viscosity of the reservoir oil can be reduced by 100 fold or more if the temperature of the oil is increased several hundred degrees. Steam injection can have substantial benefits in recovering even relatively light, low-viscosity oil. This is particularly true where such oils exist in thick, low permeability sands where present fracturing techniques are not effective. In such cases, a reduction in viscosity of the reservoir oil can sharply increase productivity. Steam injection is also useful in removing wellbore damage at injection and producing wells. Such damage is often attributable to asphaltic or paraffinic components of the crude oil which clog the pore spaces of the reservoir sand in the immediate vicinity of the well. Steam injection can be used to remove these deposits from the wellbore.
Injection of high temperature steam which may be 650.degree. F. or even higher doses, however, present some special operational problems. When the steam is injected through the tubing, there may be substantial transfer of heat across the annular space to the well casing. When the well casing is firmly cemented into the wellbore, as it generally is, the thermally induced stresses may result in casing failure. Moreover, the primary object of any steam injection process is to transfer the thermal energy from the surface of the earth to the oil-bearing formation. Where significant quantities of thermal energy are lost as the steam travels through the tubing string, the process is naturally less efficient. On even a shallow well, the thermal losses from the steam during its travel down the tubing may be so high that the initially high-temperature, superheated or saturated steam will condense into hot water before reaching the formation. Such condensation represents a tremendous loss in the amount of thermal energy that the injected fluid is able to carry into the reservoir.
A number of proposals have been advanced to combat excessive heat losses and to reduce casing temperatures in steam injection processes. It has been suggested that a temperature resistant, thermal packer be employed to isolate the annular space between the casing and injection tubing. Such equipment will reduce heat transfer due to convection between the tubing string and the casing string by forming a closed, dead-gas space in the annulus. Such specialized equipment is not only highly expensive, but does nothing to prevent radiant thermal transfer from the injection tubing.
It has been suggested that the wells be completed with a bitumastic coating. This completion technique utilizes a material to coat the casing which will melt at high temperature. When melting occurs, the casing is free to expand thus preventing the stresses which would otherwise be placed on the casing due to an increase in its temperature. This method has not proven to be universally successful in preventing casing failure. In some instances the formation may contact the casing with sufficient force to prevent free expansion and contraction of the casing during heating and cooling. Under these circumstances casing failure is possible due to the unrelieved stresses. Moreover, such a completion technique does nothing to prevent the loss of thermal energy from injection tubing.
It has been suggested that an inert gas, such as nitrogen, be introduced into the annular space between the casing and tubing and pumped down the annulus to the formation. This method requires, however, a source of gas, means for pumping the gas down the annulus, and means for separating the inert gas from the produced well fluids.
Another means which has been successfuuly employed to lower heat transfer from steam injection tubing is the heat reflector system. This is a shell of heat reflective, metal pipe which surrounds the tubing string. It is assembled in joints which are equal in length to the joints of the tubing and run into the hole with the tubing string as an integrated unit. The outer shell may be sealed at the top and bottom to prevent the entry of well fluids into the space between the steam injection tubing and the heat reflective shell. Such a system has utility in preventing the transfer of thermal energy from injection tubing due to radiation, conduction, and convection. Such a system, of course, is relatively expensive since it requires two strings of metallic pipe -- the injection tubing and the heat reflective shell. Moreover, the use of the heat reflective shell will reduce the diameter of the tubing which may be effectively employed in any given well. This can be particularly important where multiple strings of tubing are employed in a single well.
A more recent technique involves the in situ formation of silicate foam on a tubing string (see, for example, U.S. Pat. No. 3,525,399 issued Aug. 25, 1970 and U.S. Pat. No. 3,718,184 issued Feb. 27, 1973 to Bayless and Penberthy). In this process the tubing string and packer are run into the well and set into place. Then an aqueous solution of water-soluble silicate is introduced into the casing-tubing annulus above the packer. Steam is injected into the tubing string to boil the silicate solution above its boiling point and to deposit a coating of alkali metal silicate foam on the tubing.
While this technique has had very good success, it does present some operational problems. Generally, all of the excess silicate solution is not removed from the annulus by boiling during the insulating process. When the level of the solution in the annulus drops and the boiling point of the solution increases due to loss of solution water, the discharge of excess silicate solution becomes less vigorous and eventually dies. If the remaining solution is left in the annulus after steam injection is terminated, it will tend to solidify into porous and permeable mass above the packer. When subsequent operations necessitate removal of the tubing and packer from the well, the mass of silicate foam above the packer may hinder this removal. It has, therefore, generally been the practice to employ some means for removal of this excess solution after the insulation has formed on the tubing.
While it has been suggested that this excess liquid may be removed from the annular space by employing a reverse circulating device in the tubing and displacing the remaining solution from the annular space, it has been found that this displacement is at times difficult to accomplish. The remaining liquid may be highly viscous and cannot be effectively displaced with a gaseous displacing agent such as natural gas. Nor is water a totally satisfactory displacing agent. Although the dehydrated coating is not instantly soluble in water, it will deteriorate and dissolve when contacted by water for an extended period. Also, the length of time that the coating can resist deterioration by water is reduced by the relatively high temperature existing in the well following boiling of the silicate solution. Since a number of hours would be required to remove a fresh water displacing fluid from the annulus of a deep well, the use of water as a displacing fluid may cause deterioration of the silicate coating.
Other methods have recently been suggested to deal with the problem of excess solution remaining in the lower portion of the annulus after the insulation has formed on the tubing. In one method, as proposed in U.S. Pat. No. 3,664,425 issued May 23, 1972 to Penberthy et al, a foaming agent is incorporated in the silicate solution to assist in discharging more liquid during the boiling operations. In another method, as proposed in U.S. Pat. No. 3,664,424 issued May 23, 1972 to Penberthy et al, excess alkali metal silicate solution is displaced from the tubing well annular space by a fluid having a low solubility for the silicate coating. In still another method, as proposed in U.S. Pat. No. 3,861,469 issued Jan. 21, 1975 to Bayless et al, steam is injected into the tubing string until the excess silicate solution in the annular space forms a porous, permeable, and water-soluble mass. The porous and permeable mass can then be dissolved with water when it is desired to remove the tubing and packer from the well. These techniques are only partially effective and can, in certain instances, increase the cost of the process. All of these methods suggest removing excess silicate solution after the insulation has formed.